1. Field of the Invention
Embodiments of the present invention generally relate to downhole production operations conducted within a wellbore. More specifically, embodiments of the present invention relate to measuring flow rates downhole.
2. Description of the Related Art
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. When the well is drilled to a first designated depth, a first string of casing is run into the wellbore. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. Typically, the well is drilled to a second designated depth after the first string of casing is set in the wellbore. A second string of casing, or liner, is run into the wellbore to the second designated depth. This process may be repeated with additional liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing having an ever-decreasing diameter.
After a well has been drilled, it is desirable to provide a flow path for hydrocarbons from the surrounding formation into the newly formed wellbore to allow for hydrocarbon production. Therefore, after all of the casing has been set, perforations are shot through a wall of the liner string at a depth which equates to the anticipated depth of hydrocarbons. Alternatively, a liner having pre-formed slots may be run into the hole as casing. Alternatively still, a lower portion of the wellbore may remain uncased so that the formation and fluids residing therein remain exposed to the wellbore.
During the life of a producing hydrocarbon well, real-time, downhole flow data regarding the flow rate of the hydrocarbons from the formation is of significant value for production optimization. The flow rate information is especially useful in allocating production from individual production zones, as well as identifying which portions of the well are contributing to hydrocarbon flow. Flow rate data may also prove useful in locating a problem area within the well during production. Real-time flow data conducted during production of hydrocarbons within a well allows determination of flow characteristics of the hydrocarbons without need for intervention. Furthermore, real-ime downhole flow data may reduce the need for surface well tests and associated equipment, such as a surface test separator, thereby reducing production costs.
Downhole flow rate data is often gathered by use of a Venturi meter. The Venturi meter is used to measure differential pressure of the hydrocarbon fluid across a constricted cross-sectional area portion of the Venturi meter, then the differential pressure is correlated with a known density of the hydrocarbon fluid to determine flow rate of the hydrocarbon mixture. FIG. 1 depicts a typical Venturi meter 9. The Venturi meter 9 is typically inserted into a production tubing string 8 at the point at which the flow rate data is desired to be obtained. Hydrocarbon fluid flow F exists through the production tubing string 8, which includes the Venturi meter 9, as shown in FIG. 1. The Venturi meter 9 has an inner diameter A at an end (point A), which is commensurate with the inner diameter of the production tubing string 8, then the inner diameter decreases at an angle X to an inner diameter B (at point B). Diameter B, the most constricted portion of the Venturi meter 9 typically termed the “throat”, is downstream according to fluid flow F from the end having diameter A. The Venturi meter 9 then increases in inner diameter downstream from diameter B as the inner diameter increases at angle Y to an inner diameter C (typically approximately equal to A) again commensurate with the production tubing string 8 inner diameter at an opposite end of the Venturi meter 9.
Angle X, which typically ranges from 15-20 degrees, is usually greater than angle Y, which typically ranges from 5-7 degrees. In this way, the fluid F is accelerated by passage through the converging cone of angle X, then the fluid F is retarded in the cone increasing by the smaller angle Y. The pressure of the fluid F is measured at diameter A at the upstream end of the Venturi meter 9, and the pressure of the fluid F is also measured at diameter B of the throat of the Venturi meter 9, and the difference in pressures is used along with density to determine the flow rate of the hydrocarbon fluid F through the Venturi meter 9.
In conventional Venturi meters used in downhole applications, diameter A is larger than diameter B. Typically, diameter A is much larger than diameter B to ensure a large differential pressure between points A and B. This large differential pressure is often required because the equipment typically used to measure the difference in pressure between the fluid F at diameter A and the fluid F at diameter B is not sensitive enough to detect small differential pressures between fluid F flowing through diameter A and through diameter B. The extent of convergence of the inner diameter of the Venturi meter typically required to create a measurable differential pressure significantly reduces the available cross-sectional area through the production tubing string 8 at diameter B. Reducing the cross-sectional area of the production tubing string 8 to any extent to obtain differential pressure measurements is disadvantageous because the available area through which hydrocarbons may be produced to the surface is reduced, thus affecting production rates and, consequently, reducing profitability of the hydrocarbon well. Furthermore, reducing the cross-sectional area of the production tubing string with the currently used Venturi meter limits the outer diameter of downhole tools which may be utilized during production and/or intervention operations during the life of the well, possibly preventing the use of a necessary or desired downhole tool.
Venturi flow meters suffer from additional disadvantages to restricted access below the device (which may prevent the running of tools below the device) and reduced hydrocarbon flow rate. Venturi meters currently used cause significant pressure loss due to the restrictive nature of the devices. Further, because these devices restrict flow of the mixture within the tubing string, loss of calibration is likely due to erosion and/or accumulation of deposits (e.g., of wax, asphaltenes, etc.). These disadvantages may be compounded by poor resolution and accuracy of pressure sensors used to measure the pressure differences. Overcoming the poor resolution and accuracy may require the use of high contraction ratio (e.g., more restrictive) Venturi meters, thus further disadvantageously restricting the available cross-sectional area for hydrocarbon fluid flow and lowering downhole tools.
Therefore, it is desirable to provide a downhole flow meter within production tubing and other tubing strings through which fluid flows downhole within a wellbore which does not restrict the cross-sectional area available for production of hydrocarbons through the production tubing or fluid flow through other tubing. It is desirable to provide a downhole flow meter that measures flow rates within production tubing without causing a restriction in production tubing diameter. It is further desirable to provide a method of measuring downhole flow rate of hydrocarbons without restricting production of hydrocarbons or the types of tools which may be used downhole below the flow meter.